Method and System for Co2 Enhanced Oil Recovery

ABSTRACT

Methods of Enhanced Oil Recovery (EOR) from an oil reservoir by CO 2  flooding are disclosed. One method comprises producing a well stream from the reservoir; separating the well stream into a liquid phase and a gas phase with a first gas/liquid separator, wherein the gas phase comprises both CO 2  gas and hydrocarbon gas; cooling the gas phase with a first cooler; compressing the gas phase using a first compressor into a compressed stream; mixing the compressed stream with an external source of CO 2  to form an injection stream; and injecting the injection stream into the reservoir. Systems for EOR from an oil reservoir by CO 2  flooding are also disclosed.

The present invention relates to improved methods and systems forEnhanced Oil Recovery (EOR) from an oil reservoir by CO₂ flooding (CO₂EOR). In particular, it relates to utilising back-produced CO₂ from aproduction well stream.

CO₂ EOR is a secondary or tertiary recovery method for oil production,in which CO₂ is injected into an oil reservoir to increase the oilrecovery rate. The injection can be performed either by CO₂ injectionalone or in combination with traditional gas and/or water injection. Theuse of CO₂ for EOR purposes has a potential to increase the oil recoveryrate of a reservoir by up to 5 to 15 percentage points. It is also aneffective method to store considerable amounts of CO₂ underground,making this process a climate change mitigating measure. Many existingapplications of CO₂ EOR are for onshore oil fields, however its use inoffshore fields is also being developed.

Some known methods utilise CO₂ back-produced from the oil reservoiritself, instead of or in addition to CO₂ from an external source. Forexample WO 2016/108697 teaches a method whereby a gas/liquid separatorseparates the gas phase from a well stream, CO₂ is then separated fromthis gas phase by a membrane separator, the CO₂ is then compressed andcooled and injected into the reservoir for EOR. Another method is taughtin WO 2014/170466. In this method, the gas phase of a well stream isseparated from the fluid, and the gas is further separated into a CO₂stream and a hydrocarbon stream. These are then recombined in desiredquantities in order to provide a composition comprising specific CO₂ andhydrocarbon components. The method comprises cyclically alternatingbetween injecting a first composition comprising substantially pure CO₂and the CO₂/hydrocarbon composition to provide enhanced EOR.

However, there are various issues with such methods. The separation ofCO₂ from the gas phase can be complex and expensive, particularly sincethe CO₂ content in the gas phase is highly dynamic, from a few mole %just after breakthrough increasing up to 80-90 mole % or more. Not manytechnologies are applicable, particularly in an offshore, topside orsubsea, application. Indeed, many difficulties exist in the practicalimplementation of the methods described in the prior art, for example interms of avoiding hydrate formation in the separated gas and the mixtureof separated gas and external CO₂, the highly dynamic operationalconditions for the main process equipment (such as separators, heatexchangers and compressors), material issues in the liquid pipeline andprocess equipment in the existing oil processing facility due to highCO₂ content in the liquid phase and compressor requirements.

The present invention seeks to address these problems.

According to a first aspect, the present invention provides a method ofEnhanced Oil Recovery (EOR) from an oil reservoir by CO₂ flooding,comprising: producing a well stream from the reservoir; separating thewell stream into a liquid phase and a gas phase with a first gas/liquidseparator, wherein the gas phase comprises both CO₂ gas and hydrocarbongas; cooling the gas phase with a first cooler; compressing the gasphase using a first compressor into a compressed stream; mixing thecompressed stream with an external source of CO₂ to form an injectionstream; and injecting the injection stream into the reservoir.

This method provides significant advantages over the prior art. Firstly,the gas phase processed into an injection stream and injected into thereservoir comprises both CO₂ and hydrocarbons. In other words, afterseparating the gas phase from the liquid phase, the CO₂ and hydrocarbongas present in the gas phase are not further separated into individualstreams and only the CO₂ stream utilised as in prior art methods,Instead, the complete gas phase is processed and formed into aninjection stream.

Thus, at each stage in the method, and at the point of injection intothe reservoir, the gas phase/injection stream comprises both CO₂ andhydrocarbons. Moreover, it may be considered that the entire (orsubstantially the entire) gas component separated by the firstgas/liquid separator is injected (either as gas or after beingcondensed) into the reservoir. In other words, no gas fraction, inparticular no hydrocarbon fraction, is removed. The present inventorshave discovered that it is not necessary to separate these gases, thusavoiding the complex and costly CO₂ separation step frequently found inthe prior art. This is particularly the case in relation to oilreservoirs with a low Gas to Oil Ratio (GOR), since the higher pressurerequired to inject a CO₂+hydrocarbon stream is less problematic. Thus,preferably the method is utilised with a low GOR oilfield. Moreover, CO₂separation in offshore environments is particularly challenging, thusthe method of the invention provides particular advantages in relationto such environments. The injection, in the invention, of a streamformed from the complete gas phase simplifies the process and provides acommercially viable solution.

It will be appreciated that this first aspect of the invention defines amethod carried out after CO₂ breakthrough into the well stream hasoccurred, in other words CO₂ is being back-produced from the reservoirinto the well stream. Thus, CO₂ is present in the gas phase separated bythe first gas/liquid separator, and is then, after the variousprocessing steps, re-injected into the reservoir to enhance the oilrecovery by CO₂ flooding. Prior to this method of the invention beingcarried out, in a first phase of operation prior to CO₂ breakthrough, inorder to inject CO₂ into the reservoir, CO₂ must be supplied only froman external source. An aspect of the invention including also this firstphase of operation is described later.

It will be appreciated that by “an external source of CO₂” means CO₂ notproduced from the reservoir, but rather provided from a source externalto the EOR process. The CO₂ may be pure CO₂, and may come from naturalsources of CO₂ or CO₂ captured from industrial processes. For example,CO₂ may be CO₂ captured from industrial processes such as cementproduction and ammonia production, or captured from exhaust gases frompower and heat production, onshore or offshore. The external CO₂ may begaseous CO₂, but is most preferably liquid CO₂.

Mixing with external CO₂ is particularly beneficial in a first periodafter CO₂ breakthrough. In this early phase the flow rate of the gasfrom the well stream may be quite low and comprise a large proportion ofmethane and the external CO₂ is needed to maintain injection flow-rate.After CO₂ breakthrough, the content of CO₂ in the well stream willincrease, and the need for external CO₂ will decrease. At some point,the back-produced CO₂ may be sufficient that in a further phase ofoperation, after the method of the invention, the supply of external CO₂is stopped.

Mixing the gas phase with an external source of CO₂ provides furthersignificant advantages. In a first period after CO₂ breakthrough, thegas phase flow from the first compressor (the output of the compressoris generally gas, possibly with small amount of liquid) will be low andcontain high concentrations of methane. This gas should preferably becondensed prior to injection into the reservoir. However, a very highpressure from the first compressor would be required for condensation bysea-water alone, and there would be a high risk of hydrate formation.However, by mixing the gas phase with external CO₂ (preferably liquidCO₂), the gas phase may condense/dissolve during the mixing process.Consequently, after mixing, the injection stream may preferably be aliquid phase or a gas+liquid phase.

In situations where the injection stream is a gas phase (or has asignificant proportion of gas phase) after mixing, a subsequent coolingstep may be carried out by a second cooler to condense the gas fractionso that the injection stream is in the liquid phase (or is substantiallyin the liquid phase with only a low percentage of gas).

Alternatively, the compressed gas phase leaving the first compressor maybe cooled and condensed into a liquid phase or liquid+gas phase by asecond cooler prior to mixing.

The second cooler may be an active cooler, preferably with seawatercirculation. The operational parameters, mainly temperatures, need to becontrolled to avoid hydrate formation.

By cooling/condensing the compressed stream, its density increases andthereby the required injection pressure is reduced (high density gives apressure increase down the injection piping).

The first compressor may preferably be a liquid tolerant compressorsince liquid may form after the first cooler. If the compressor is notliquid tolerant, an additional gas/liquid separator may be requiredupstream the compressor. Most likely, an additional liquid pump would berequired to bring the liquid phase back into the main gas liquidseparator or directly into the liquid being transported to the oilprocessing facility. Such complexity can be avoided by using a liquidtolerant compressor.

Preferably the first cooler is an active cooler so that the coolingtemperature may be controlled in order to both prevent hydrate formationand control the compressor inlet temperature.

Hydrates are to be avoided both in the first and second coolers sincethey can create flow blockages. The hydrate formation temperature willdecide the minimum temperature in the cooling process. The hydrateformation temperature will depend on the gas composition. In a firstperiod after CO₂ breakthrough, the gas phase will have a high methanecontent and the hydrate formation temperature will be highest. Later,when the gas phase comprises more CO₂, the hydrate formation temperaturewill decrease. For optimum injection, it is desired to have as low astemperature as possible (low temperature means high density) but it isnecessary to keep above the hydrate formation temperature. For theactual compositions and operational pressures, the hydrate temperaturemay typically be in the range of 5-25° C.

Generally, the gas phase separated by the first gas/liquid separatorwill comprise a small amount of water vapour (i.e. evaporated water) inaddition to CO₂ and hydrocarbon gas, or the gas phase may be saturatedwith water. Whilst the gas phase may be dehydrated to remove the water,thereby reducing the corrosive effect of the gas phase, preferably thegas phase is not dehydrated so as to avoid the associated processcomplexity.

The liquid phase separated by the first gas/liquid separator willgenerally comprise water (formation water), oil and dissolved CO₂.

Typically, the well stream is choked, generally to a pre-definedpressure, prior to separating the well stream into a liquid phase and agas phase. This will release a gas from the well stream, which is thenseparated by the first gas/liquid separator. The pressure to which thewell stream is choked determines the partial pressure/content of CO₂ inthe gas-phase, and the content of CO₂ in the liquid phase. A lowerpressure means a lower CO₂ content in the liquid. One skilled in the artwould readily appreciate how to select a suitable pre-defined pressuredependent on the particular scenario.

The separation pressure will influence the compressor requirements andthe power required for the stream to be injected. It will determinewhether, if the liquid phase is sent to an oil processing facility, theliquid phase needs to be pressure boosted or not. If pressure boostingis required, a pump will be provided for the liquid phase.

Moreover, the separation pressure will determine whether carbon steelcan be used in piping used to convey the liquid phase downstream theseparator, e.g. piping connecting with an oil processing facility, orwhether corrosion resistant materials are required. The higher thepressure, the more CO₂ there will be in the liquid phase. Due to thecorrosive effect of CO₂, if the CO₂ in the liquid phase is too high,some pipeline materials such as carbon steel will suffer from corrosionto an unacceptable extent. Thus, at higher pressures, the larger amountsof CO₂ in the liquid phase requires downstream piping to be manufacturedfrom corrosion resistant material, such as stainless steel. Thus, in oneembodiment, the liquid phase is transported to an oil processingfacility through corrosion-resistant, e.g. stainless steel, piping.Other corrosion-resistant materials may be used, such as nickel basedalloys, but these are generally more expensive. Copper based alloys mayalso be viable. Material selection may also depend on temperature.Whilst the need for corrosion-resistant materials may have somedisadvantages, the higher pressure means that additional pumping for theliquid phase may not be required. Moreover, if lower pressures were usedin order to avoid the need for corrosion-resistant materials, a moretechnically complex compressor solution would be required.

In one embodiment, prior to separating the well stream into a liquidphase and a gas phase, the well stream is heated. This is preferably bymeans of a heat exchanger, more preferably by a heat exchanger utilisingheat supplied by the first compressor so as to minimise the externalenergy requirement.

Whilst the method of the invention can be used with onshore reservoirs,it has particular application for offshore oil reservoirs, for exampleoffering the particular advantages discussed above. In the case ofoffshore (i.e. subsurface) reservoirs, the entire method of theinvention may be carried out subsea.

Alternatively, at least the steps of separating the well stream, coolingthe gas phase and compressing the gas phase may in fact be carried outabove the sea (topside), preferably on a platform or floater. The stepsof mixing and cooling the injection stream may also be carried out abovethe sea.

In another embodiment, the step of separating the well stream is carriedout subsea, whilst the steps of cooling the gas phase and compressingthe gas phase are carried out above the sea, preferably on a platform orfloater. This reduces the equipment topside and the amount ofhydrocarbon inventory topside. This makes it easier to use an unmannedtopside without a flare system. Furthermore, by carrying out thegas/liquid separation at the seabed, the liquid phase can be sentdirectly to the oil processing facility, and an extra liquid riser fromthe separation process topside to the seafloor (and then up to the oilprocessing facility) is avoided.

The well stream gas flow rate after CO₂ breakthrough will be highlydynamic (mainly increasing), especially in a first period, before a morestable situation is reached. To handle this dynamic situation, aftercompressing the gas phase, part of the compressed gas phase may berecycled into the well stream upstream the gas/liquid separator.Alternatively, the compressor recycle flow can be mixed into the gasphase downstream the gas/liquid separator. This compressor recycleprovides more stable conditions for the separator operation, as itallows the separator to operate within narrower gas and liquid loadranges during the lifetime of the oil reservoir, which simplifies theoperation and control of the separator.

Furthermore, after compressing the gas phase, part of the compressedstream may be used to form an anti-surge flow which is directed into thegas phase downstream the first gas/liquid separator and upstream thefirst cooler. Alternatively, gas from downstream the compressor may bemixed with the well stream upstream the first gas/liquid separator. Inone embodiment, a combined compressor recycle and anti-surge line may beprovided.

The injection stream may be pumped by a booster or injection pump toincrease the pressure thereof prior to injection in the reservoir. Sucha pumping step will generally be carried out after cooling e.g. by thesecond cooler. If the injection stream is liquid, this can be pumped byone common pump. Pumping is advantageous since it requires lessenergy/power than compression.

In one embodiment, the first compressor may in fact comprise twocompressors arranged in series (or, it may be considered that aftercompressing the gas phase with a first compressor, the compressed streamis then further compressed with an additional compressor). Thus, aftercooling the gas phase with the first cooler, it is compressed in twostages. Compression in more than one stage may be desirable if therequired pressure ratio is higher than can be achieved by onecompressor. However, it is preferable to use only one compressor ifpossible, in order to minimise cost and complexity.

It will be appreciated that the injection stream is CO₂-rich, since itcomprises both CO₂ from the well stream and CO₂ from an external source.In one example, at the point of injection into the reservoir, theinjection stream comprises 85 to 95 mole % CO₂.

As mentioned previously, following gas/liquid separation, the liquidphase may be transported to an oil processing facility. Generally, thiswill be an existing oil processing facility. Since the liquid phase willstill comprise some dissolved CO₂, it will be corrosive, thus preferablythe liquid phase is transported through corrosion-resistant piping.

As mentioned above, if it were desired to use non-corrosion resistantpiping to transport the liquid phase, a low pressure could be used inthe first gas/liquid separator to reduce the CO₂ content in the liquidphase to a level allowing the use of e.g. carbon steel piping. However,this would require a more technically complex compressor solution. Thepresent inventors have found a solution to this problem, by using amultiple-stage separation process. In such a preferred process, afterseparation in the first gas/liquid separator, the liquid phase is chokedto a lower pressure (i.e. a pressure lower than with which it exits thefirst gas/liquid separator) such that a second gas phase comprising CO₂and hydrocarbon gas is released from the liquid phase. This second gasphase and liquid phase are separated in a second gas/liquid separator.By doing this, the partial pressure of CO₂ in the liquid phase leavingthe second gas/liquid separator can be made low enough to allow for acarbon steel pipeline transporting the liquid phase e.g. to an oilprocessing facility, and also within the oil processing facility itself.In other words, since there is less CO₂ in the liquid phase, the liquidphase is less corrosive, so corrosion-resistant piping is notnecessarily required and carbon steel can instead be used.

The particular partial pressure of CO₂ which is low enough to allow fora carbon steel pipeline will depend e.g. on temperature, oil andformation water component. However, in one example, carbon steel may beused with a CO₂ pressure below 5 barn (bar absolute) (500 kPa).

The second gas phase separated by the second gas/liquid separator ispreferably combined with the gas phase separated by the first gas/liquidseparator. Preferably this combining is carried out prior to cooling bythe first cooler and compressing by the first compressor. Thus, thiscombined gas phase is then cooled by the first cooler, compressed by thefirst compressor; mixed with an external source of CO₂ and injected intothe reservoir.

Generally, prior to being combined with the first gas phase, variousprocessing steps are carried out on the second gas phase. In oneembodiment, after being separated by the second gas/liquid separator,the second gas phase is cooled with a third cooler and then compressed,before it is combined with the gas phase separated by the firstgas/liquid separator. The second gas phase may be compressed by onecompressor. However, the gas flowrate from the second gas/liquidseparator is substantially lower than that from the first gas/liquidseparator, and to bring this gas up to the same pressure as the firstgas phase multiple compressors are most likely needed. Thus, two or morecompressors arranged in series may be used. These may be smaller thanthe first compressor compressing the first gas phase. If the totalpressure ratio is low enough, intermediate cooling between thecompressors is not needed, but may be required for higher pressureratios. The compressors are preferably liquid tolerant, especially thefirst of two compressors arranged in series. Alternatively, dry gascompressors may be used, but upstream separators/scrubbers would then berequired. The power requirement for two small compressors may be lessthan 10% of the main (first) compressor.

The operational conditions of the compressor(s) compressing the secondgas phase are most likely constant enough that compressor recycle is notnecessary. However, situations may arise where compressor recycle isneeded, and in this case, after compressing the second gas phase, partof the second gas phase is recycled into the liquid phase upstream thesecond gas/liquid separator. Alternatively, it may be recycled into thesecond gas phase downstream the second gas/liquid separator.

After compressing the second gas phase, an anti-surge flow may be formedfrom part of the second gas phase. This may be directed into the secondgas phase downstream the second gas/liquid separator and upstream thethird cooler; or upstream the second gas/liquid separator.

As an alternative to compressing the second gas phase with a compressor,the pressure of the second gas phase may be increased by an ejectorprior to being combined with the first gas phase separated by the firstgas/liquid separator. The ejector can advantageously be powered bymotive gas flow from downstream the first compressor. This simplifiesthe process and removes the need for the third cooler.

Whilst the second separation step using a second gas/liquid separator isdescribed above as an optional feature in relation to the first aspectof the invention, this two-stage separation process is seen as aninvention in its own right. Thus, accordingly, in a second aspect, theinvention provides a method of Enhanced Oil Recovery (EOR) from an oilreservoir by CO₂ flooding, comprising: producing a well stream from thereservoir; separating the well stream into a liquid phase and a firstgas phase with a first gas/liquid separator; reducing the pressure ofthe liquid phase to release a second gas phase and separating thissecond gas phase from the liquid phase with a second gas/liquidseparator; combining the first and second gas phases into a combined gasphase; cooling the combined gas phase with a first cooler; compressingthe combined gas phase into an injection stream with a first compressor;and injecting the injection stream into the reservoir.

It will be appreciated that many of the various preferred and optionalfeatures described above in relation to the first aspect of theinvention are also applicable to this second aspect. Some of these willnow be described, however the particular advantages of the preferredfeatures may not be repeated here for brevity; instead, reference may bemade to the advantages described above in relation to the first aspect.

This aspect of the invention is not limited to the gas phase comprisingboth CO₂ gas and hydrocarbon gas. Thus, this method may be utilised insituations where CO₂ gas is separated from the hydrocarbon gas. Whilst,as described above in relation to the first aspect, it is advantageousto use the entire gas phase and not only separated CO₂, the method ofthe second aspect will provide advantages even where CO₂ is separatedfrom hydrocarbons.

Moreover, this aspect of the invention is not limited to an externalsource of CO₂ being mixed with the compressed stream from the firstcompressor. Whilst, as described above in relation to the first aspect,this mixing with external CO₂ offers various advantages, the method ofthe second aspect will provide advantages independently of the use ofexternal CO₂.

By carrying out the two-stage gas/liquid separation of the second aspectof the invention, the partial pressure of CO₂ in the liquid phaseleaving the second gas/liquid separator can be low enough to allow for acarbon steel pipeline transporting the liquid phase e.g. to an oilprocessing facility, and also within the oil processing facility itself.In other words, since there is less CO₂ in the liquid phase, the liquidphase is less corrosive, so corrosion-resistant piping is notnecessarily required and carbon steel can instead be used. This ishighly advantageous. The particular partial pressure of CO₂ which is lowenough to allow for a carbon steel pipeline will depend e.g. ontemperature, oil and formation water component. However, in one example,carbon steel may be used with a CO₂ pressure below 5 bara (500 kPa).

Moreover, this is advantageous in terms of the oil processing facilitywhich would likely experience corrosion problems with high levels ofCO₂. Thus, the two-stage separation process is also advantageous inavoiding the need for significant modification to the oil processingfacility.

Whilst the second aspect of the invention describes a two-stagegas/liquid separation, it will be appreciated that in some situationsmore than two stages may be provided. In such a multi-stage gas/liquidseparation process, for example, after separating the second gas phasefrom the liquid phase with a second gas/liquid separator, the pressureof the liquid phase may be further reduced to release a third gas phase.This third gas phase may be separated from the liquid phase with a thirdgas/liquid separator. All of the first, second and third gas phases maybe combined into a combined gas phase which is then processed by thefirst cooler, first compressor and then injected into the reservoir.

It will be appreciated that this second aspect of the invention definesa method carried out after CO₂ breakthrough into the well stream hasoccurred, in other words CO₂ is being back-produced from the reservoirinto the well stream. Thus, CO₂ is present in the gas phase separated bythe first gas/liquid separator, and is then, after the variousprocessing steps, re-injected into the reservoir to enhance the oilrecovery by CO₂ flooding. Prior to this method of the invention beingcarried out, in a first phase of operation prior to CO₂ breakthrough, inorder to inject CO₂ into the reservoir, CO₂ must be supplied only froman external source. An aspect of the invention including also this firstphase of operation is described later.

In one embodiment, the first gas phase and the second gas phase eachcomprise both CO₂ and hydrocarbon gas. They may each also furthercomprise water vapour. The injection stream injected into the reservoirpreferably comprises both CO₂ and hydrocarbons, in other words noseparation process has been carried out to separate and use only theCO₂, however as described above the method can be used even in caseswhere the CO₂ is separated.

The first cooler is preferably an active cooler so that the coolingtemperature may be controlled in order to both prevent hydrate formationand control the compressor inlet temperature.

Furthermore, the first compressor may preferably be a liquid tolerantcompressor since liquid may form after the first cooler. If thecompressor is not liquid tolerant, an additional gas/liquid separatormay be required upstream the compressor. Most likely, an additionalliquid pump would be required to bring the liquid phase back into themain gas liquid separator or directly into the liquid being transportedto the oil processing facility. Such complexity can be avoided by usinga liquid tolerant compressor.

Whilst, as mentioned above, this second aspect of the invention does notrequire an external source of CO₂ to be mixed into the injection stream.In one preferred embodiment such an external source of CO₂ is mixed intothe injection stream prior to injecting the injection stream into thereservoir. This external source of CO₂ may be gaseous CO₂, but morepreferably is liquid CO₂.

The injection stream into which the external source of CO₂ is mixed maycomprise a gas phase, and the step of mixing the external source of CO₂into the injection stream may cause the gas phase of the injectionstream to at least partially condense or dissolve in the external sourceof liquid CO₂.

The method may further comprise cooling the injection stream with asecond cooler, preferably by active cooling, either before or after theexternal source of CO₂ is mixed into the injection stream. This coolingstep may condense at least part of a gas phase in the injection streaminto liquid.

In one embodiment, the first compressor may in fact comprise twocompressors arranged in series (or, it may be considered that aftercompressing the gas phase with a first compressor, the compressed streamis then further compressed with an additional compressor). Thus, aftercooling the gas phase with the first cooler, it is compressed in twostages. Compression in more than one stage may be desirable if therequired pressure ratio is higher than can be achieved by onecompressor. However, it is preferable to use only one compressor ifpossible, in order to minimise cost and complexity.

Preferably, the well stream is choked to a pre-defined pressure prior toseparating the well stream into a liquid phase and a first gas phase.This will release a gas from the well stream, which is then separated bythe first gas/liquid separator. The pressure to which the well stream ischoked determines the partial pressure/content of CO₂ in the gas-phase,and the content of CO₂ in the liquid phase. A lower pressure means alower CO₂ content in the liquid.

Prior to separating the well stream into a liquid phase and a first gasphase, the well stream may be heated. This is preferably done via a heatexchanger, more preferably by a heat exchanger utilising heat suppliedby the first compressor so as to minimise the external energyrequirement.

Whilst the method may be used with onshore reservoirs, the method isparticularly useful for offshore reservoirs. In the case of an offshorereservoir, the entire method of this aspect of the invention may becarried out subsea. Or, the step of separating the well stream into aliquid phase and a first gas phase may be carried out subsea, and thesubsequent steps are carried out above the sea, preferably on a platformor floater. Or, at least the following steps may be carried out abovethe sea, preferably on a platform or floater: separating the well streaminto a liquid phase and a first gas phase with a first gas/liquidseparator; reducing the pressure of the liquid phase to release a secondgas phase and separating this second gas phase from the liquid phasewith a second gas/liquid separator; combining the first and second gasphases into a combined gas phase; cooling the combined gas phase with afirst cooler; and compressing the combined gas phase into an injectionstream with a first compressor.

The liquid phase from the second gas/liquid separator, comprising oil,water and dissolved CO₂ will generally be transported to an oilprocessing facility. The second gas/liquid separation process will havesufficiently reduced the CO₂ content in the liquid so thatcorrosion-resistant piping is not required to transport the liquid.Instead, carbon steel piping may be used. However, the liquid will stillcause some low level of corrosion, and to protect against this acorrosion control method may be used such as injecting a film formingcorrosion inhibitor into the liquid phase to limit the corrosion rate ofthe pipeline and process equipment and piping.

Preferably, the second gas phase is cooled by a third cooler and thencompressed prior to being combined with the first gas phase. Thiscompression may be carried out by one compressor, or in two stages bytwo (or more) compressors arranged in series. After compressing thesecond gas phase, part of the compressed second gas phase may be used toform an anti-surge flow which is directed into the second gas phasedownstream the second gas/liquid separator and upstream the thirdcooler.

As an alternative to compressing the second gas phase with a compressor,the pressure of the second gas phase may be increased by an ejectorprior to being combined with the first gas phase separated by the firstgas/liquid separator. The ejector can advantageously be powered bymotive gas flow from downstream the first compressor.

The well stream gas flow rate after CO₂ breakthrough will be highlydynamic (mainly increasing), especially in a first period, before a morestable situation is reached. To handle this dynamic situation, aftercompressing the gas phase, part of the compressed gas phase may berecycled into the well stream upstream the gas/liquid separator.Alternatively, the compressor recycle flow can be mixed into the gasphase downstream the gas/liquid separator. This compressor recycleprovides more stable conditions for the separator operation, as itallows the separator to operate within narrower gas and liquid loadranges during the lifetime of the oil reservoir, which simplifies theoperation and control of the separator.

Furthermore, after compressing the gas phase, part of the compressedstream may be used to form an anti-surge flow which is directed into thegas phase downstream the first gas/liquid separator and upstream thefirst cooler. Alternatively, gas from downstream the compressor may bemixed with the well stream upstream the first gas/liquid separator. Inone embodiment, a combined compressor recycle and anti-surge line may beprovided.

The injection stream may be pumped by a booster or injection pump toincrease the pressure thereof prior to injection in the reservoir. Sucha pumping step will generally be carried out after cooling e.g. by thesecond cooler. If the injection stream is liquid, this can be pumped byone common pump. Pumping is advantageous since it requires lessenergy/power than compression.

In the first and second aspects of the invention described above, theprocess of recycling part of the compressed gas in order to provide morestable operation in the presence of a highly dynamic gas flow rate isdescribed as an optional feature. However, this is more generallyapplicable and is considered as an invention in its own right. Thus,according to a third aspect, the invention provides a method used inEnhanced Oil Recovery (EOR) from an oil reservoir by CO₂ flooding,comprising: producing a well stream from the reservoir; separating thewell stream into a liquid phase and a gas phase with a gas/liquidseparator;

compressing the gas phase using a compressor; and recycling part of thecompressed gas phase into the well stream upstream the gas/liquidseparator or into the gas phase downstream the gas/liquid separator.

It will be appreciated that many of the various preferred and optionalfeatures described above in relation to the first and second aspects ofthe invention are also applicable to this third aspect. Some of thesewill now be described, however the particular advantages of thepreferred features may not be discussed here to avoid repetition;instead, reference may be made to the advantages described above inrelation to the first and second aspects.

This aspect of the invention is not limited to the gas phase comprisingboth CO₂ gas and hydrocarbon gas. Thus, this method may be utilised insituations where CO₂ gas is separated from the hydrocarbon gas. Whilst,as described above in relation to the first aspect, it is advantageousto use the entire gas phase and not only separated CO₂, the method ofthe third aspect will provide advantages even where CO₂ is separatedfrom hydrocarbons.

Moreover, this aspect of the invention is not limited to an externalsource of CO₂ being mixed with the compressed stream from the firstcompressor. Whilst, as described above in relation to the first aspect,this mixing with external CO₂ offers various advantages, the method ofthe third aspect will provide advantages independently of the use ofexternal CO₂.

By providing a compressor recycle flow, more stable conditions for thegas/liquid separator operation and the compressor operation areprovided, by allowing the separator to operate within narrower gas andliquid load ranges during the lifetime of the oil reservoir, whichsimplifies the operation and control of the separator. Such a method maybe used as part of any method of EOR by CO₂ flooding, where a compressoris used, in order to provide such advantages.

After compressing the gas phase, part of the compressed gas phase may beused to form an anti-surge flow which is directed into the gas phasedownstream the gas/liquid separator and upstream the cooler. In oneembodiment, a combined recycle and anti-surge line may be provided torecycle the part of the compressed gas phase and also provide theanti-surge flow. This reduces the pipework required.

The gas phase may be cooled with a first cooler, prior to compressingthe gas phase. Part of the compressed gas phase may be recycled into thegas phase downstream the gas/liquid separator and upstream the firstcooler.

The first compressor may preferably be a liquid tolerant compressorsince liquid may form after the first cooler. If the compressor is notliquid tolerant, an additional gas/liquid separator may be requiredupstream the compressor. Most likely, an additional liquid pump would berequired to bring the liquid phase back into the main gas liquidseparator or directly into the liquid being transported to the oilprocessing facility. Such complexity can be avoided by using a liquidtolerant compressor.

The well stream may be choked to a pre-defined pressure prior toseparating the well stream into the liquid phase and the gas phase. Thiswill release a gas from the well stream, which is then separated by thefirst gas/liquid separator. The pressure to which the well stream ischoked determines the partial pressure/content of CO₂ in the gas-phase,and the content of CO₂ in the liquid phase. A lower pressure means alower CO₂ content in the liquid. Part of the compressed gas phase may berecycled into the well stream upstream of the gas/liquid separator anddownstream the choke.

In one embodiment, the gas phase comprises CO₂ and hydrocarbon gas. Itmay also comprise a small amount of water vapour, or the gas phase maybe saturated with water.

The first cooler is most preferably an active cooler so that the coolingtemperature may be controlled in order to both prevent hydrate formationand control the compressor inlet temperature.

In one embodiment, prior to separating the well stream into a liquidphase and a gas phase, the well stream is heated. This is preferably bymeans of a heat exchanger, more preferably by a heat exchanger utilisingheat supplied by the first compressor so as to minimise the externalenergy requirement.

Whilst the method of the third aspect can be used with onshorereservoirs, it has particular application for offshore oil reservoirs.

Whilst, as mentioned above, this third aspect of the invention does notrequire the mixing of an external source of CO₂, in one preferredembodiment an external source of CO₂ is mixed into the gas phase to forman injection stream. This injection stream is then injected into thereservoir. This external source of CO₂ may be gaseous CO₂, but morepreferably is liquid CO₂. The injection stream may be cooled with asecond cooler. Its pressure may be increased by pumping prior toinjecting into the reservoir.

The liquid phase may be transported to an oil processing facility.Generally, this will be an existing oil processing facility.

As described previously, prior to the method of the first aspect of theinvention being carried out (and indeed prior to any of the methods ofthe invention being carried out), there will generally be an earlierphase of operation prior to CO₂ breakthrough in which CO₂ is suppliedonly from an external source. Thus, in another aspect, the inventionprovides a method of Enhanced Oil Recovery (EOR) from an oil reservoirby CO₂ flooding, comprising: a first phase comprising injecting CO₂ froma source external to the oil reservoir into the reservoir, and a secondphase comprising any of the above described methods.

Preferably, prior to commencement of the second phase, it is determinedthat the back-produced CO₂ in a well-stream produced from the reservoirexceeds a threshold value or it is determined that the CO₂/methane ratioin a well-stream produced from the reservoir exceeds a threshold value.

If it is determined that the CO₂ or CO₂/methane ratio does not exceed athreshold value, and thus the second phase has not yet commenced, themethod may further comprise directing the well stream from the reservoirto an oil processing facility. Thus, during the first phase ofoperation, the well stream is directed to the oil processing facility.

In the first phase of operation when CO₂ is supplied only from anexternal source, the pressure of the external CO₂ may not be sufficientfor direct injection into the reservoir, so preferably the methodcomprises pumping the external CO₂ to a sufficient pressure prior toinjection. This pressure will depend on the pressure in the reservoir atthe injection point, the necessary excess pressure to drive the CO₂ intothe reservoir, the static pressure increase from the injection templateto the injection point and the pressure drop in the injection pipe.

In the first phase of operation in which only CO₂ from an externalsource is injected into the reservoir, the injection stream thereforecomprises 100 mole % CO₂. During the second phase of operation, theinjection stream may comprise 85-95 mole % CO₂.

There may be a third phase of operation after the second phase whereinthe mixing of external CO₂ is stopped. Preferably, the method includesthe step of determining whether the CO₂ in the injection stream exceedsa certain value in the second phase, and if this value is exceeded, themixing of external CO₂ is stopped. This value represents a sufficientquantity of backproduced CO₂ that external CO₂ is not required.

The invention also extends to systems arranged to perform any of themethods as described above.

In one further aspect, the invention provides an enhanced oil recoverysystem, comprising: a producer arranged to produce a well stream from areservoir a first gas/liquid separator arranged to separate the wellstream into a liquid phase and a gas phase comprising both CO₂ gas andhydrocarbon gas; a first cooler arranged to cool the gas phase; a firstcompressor arranged to compress the cooled gas phase into a compressedstream; a mixer arranged to mix the compressed stream with an externalsource of CO₂ to form an injection stream; and injection piping arrangedto inject the injection stream into the reservoir.

This is a system corresponding to the method of the first aspect of theinvention described above. Many advantages described in relation to themethod and its preferred features are also clearly applicable to thissystem and its preferred features as described below. However, not allof these advantages will be described here in order to avoid repetition.

The first cooler may be an active cooler. The first compressor may be aliquid tolerant compressor.

The system may further comprise a choke arranged upstream the firstgas/liquid separator to choke the well stream to a pre-defined pressure.

The system may further comprise a heat exchanger arranged upstream thefirst gas/liquid separator to heat the well stream. In this heatexchanger the well-stream may be heated in heat exchange with warm gasfrom the compressor discharge, provided e.g. by suitable piping.

Whilst the system may be used with an oil reservoir in any location, itis preferably configured for operation with an offshore reservoir. Insuch a case, the system may therefore be located entirely subsea. Inanother embodiment, the first gas/liquid separator, first cooler andfirst compressor is in fact located above the sea, preferably on aplatform or a floater. In a further embodiment, the first gas/liquidseparator is located subsea whilst the first cooler and first compressorare located above the sea, preferably on a platform or floater.

The system may further comprise a recycle line connecting betweendownstream the first compressor and either upstream the first gas/liquidseparator or downstream the first gas/liquid separator. The recycle lineis arranged to recycle part of the compressed gas phase into either thewell stream upstream the first gas/liquid separator, or the gas phasedownstream the first gas/liquid separator.

The system may also further comprise an anti-surge line connectingbetween downstream the first compressor and a point downstream the firstgas/liquid separator and upstream the first cooler. The anti-surge lineis arranged to provide an anti-surge flow of compressed gas phase intothe gas phase downstream the first gas/liquid separator and upstream thefirst cooler. A combined recycle and anti-surge line may be provided.

In one embodiment, the first compressor may in fact comprise twocompressors arranged in series (or, it may be considered that downstreamthe first compressor is an additional compressor) to provide compressionin two stages. Compression in more than one stage may be desirable ifthe required pressure ratio is higher than can be achieved by onecompressor. However, it is preferable to use only one compressor ifpossible, in order to minimise cost and complexity.

A second cooler may be provided downstream the first compressor to coolthe compressed gas phase prior to being input to the mixer, ordownstream the mixer to cool the injection stream. A booster pump orinjection pump may be provided downstream the second cooler to pump theinjection stream, prior to the injection stream being supplied to theinjection piping for injection into the reservoir.

Corrosion-resistant piping is preferably used within the implementationof the system of this aspect of the invention. The system may furthercomprise piping arranged to transport the liquid phase to an oilprocessing facility. Preferably, this piping is corrosion-resistant, forexample made form stainless steel.

In one particularly preferred embodiment, the system further comprises asecond choke arranged to choke the liquid phase to a lower pressure soas to release a second gas phase. A second gas/liquid separator is thenarranged to separate the second gas phase from the liquid phase. Pipingmay be provided to connect the second gas phase with the first gas phasesuch that the gas phases mix together.

A third cooler may be arranged downstream the second gas/liquidseparator to cool the second gas phase. Further, a compressor may bearranged downstream the third cooler to compress the second gas phase.Such components would generally be provided upstream any pipingconnecting the second gas phase with the first gas phase.

In yet another aspect, the invention provides an enhanced oil recoverysystem, comprising: a producer arranged to produce a well stream from areservoir; a first gas/liquid separator arranged to separate the wellstream into a liquid phase and a gas phase; a choke arranged to reducethe pressure of the liquid phase so as to release a second gas phase; asecond gas/liquid separator arranged to separate the second gas phasefrom the liquid phase; piping or a mixer arranged to combine or mix thefirst and second gas phases into a combined gas phase; a first coolerarranged to cool the combined gas phase; a first compressor arranged tocompress the combined gas phase into an injection stream; and injectionpiping arranged to inject the injection stream into the reservoir.

This is a system corresponding to the method of the second aspect of theinvention described above. Many advantages described in relation to themethod and its preferred features are also clearly applicable to thissystem and its preferred features as described below. However, theadvantages will not all be described here in order to avoid repetition.

In this system, the first cooler is preferably an active cooler. Thefirst compressor is preferably a liquid tolerant compressor.

The system may further comprise an external source of CO₂, preferablyliquid CO₂. A mixer may be arranged to mix CO₂ from the external sourceof CO₂ with the injection stream.

A second cooler may be provided. In one embodiment this is arrangedupstream the mixer to cool the injection stream prior to mixing with theCO₂, and in another embodiment it is arranged downstream the mixer tocool the injection stream after mixing with the CO₂. Preferably, thesecond cooler is an active cooler. A booster pump or injection pump maybe provided downstream the second cooler to pump the injection stream,prior to the injection stream being supplied to the injection piping forinjection into the reservoir.

A second choke may be arranged to choke the well stream upstream thefirst gas/liquid separator to a predefined pressure.

Piping may be provided to transport the liquid phase to an oilprocessing facility. Due to the two stage separation, the liquid phasewill comprise a low enough amount of CO₂ that corrosion resistant pipingmay not be required. Consequently, the piping may be made of carbonsteel. However, the liquid will still cause some low level of corrosion,so to protect against this a source of film forming corrosion inhibitormay be arranged for injection into the liquid phase.

In one embodiment, the system further comprises a third cooler arrangeddownstream the second gas/liquid separator to cool the second gas phase.Furthermore, a compressor may be arranged downstream the third cooler tocompress the second gas phase. Alternatively, instead of a compressorfor compressing the second gas phase, the system may comprise an ejectorarranged to increase the pressure of the second gas phase. The ejectoris preferably powered by motive gas flow from downstream the firstcompressor.

In yet another aspect, the invention provides a system for use inenhanced oil recovery, comprising: a producer arranged to produce a wellstream from a reservoir; a gas/liquid separator arranged to separate thewell stream into a liquid phase and a gas phase; a compressor arrangedto compress the gas phase; a recycle line arranged to direct compressedgas from downstream the compressor to either upstream the gas/liquidseparator or downstream the gas/liquid separator, such that the recycleline recycles part of the compressed gas phase into either the wellstream upstream the gas/liquid separator, or the gas phase downstreamthe gas/liquid separator.

This is a system corresponding to the method of the third aspect of theinvention described above. Many advantages described in relation to themethod and its preferred features are also clearly applicable to thissystem and its preferred features as described below. However, not allof these will be described here in order to avoid repetition.

In one embodiment, a cooler is arranged upstream the compressor to coolthe gas phase. Preferably, this is an active cooler.

The system may further comprise an anti-surge line arranged to directcompressed gas as an anti-surge flow from downstream the compressor todownstream the gas/liquid separator and upstream the cooler. In oneembodiment, the anti-surge line and the recycle line may be provided asa combined line.

A choke may be arranged downstream the gas/liquid separator to reducethe pressure of the well stream. In this case, the recycle line may bearranged to direct compressed gas into the well stream upstream thegas/liquid separator and downstream the choke.

Preferably, the system further comprises an external source of CO₂,preferably liquid CO₂. In this case, a mixer may be arranged to mix CO₂from the external source of CO₂ into the gas phase to form an injectionstream.

In one embodiment, a second cooler is arranged to cool the injectionstream. Optionally, a pump may be arranged to pump the injection stream.Generally, the system further comprises injection piping for injectingthe injection stream into the reservoir.

The invention further provides an enhanced oil recovery system,comprising: an external source of CO₂; injection piping arranged toinject the external source of CO₂ into an oil reservoir; a device formonitoring a CO₂ content or CO₂/methane ratio back-produced in a wellstream from the oil reservoir; a device for determining when a CO₂content or CO₂/methane content threshold is exceeded; and a systemaccording to any of the embodiments described above; wherein the systemfurther comprises piping to bypass the elements of the system accordingto any of the embodiments described above downstream the producer anddirect the well stream to an oil processing facility, in the event thatthe threshold is not met. Preferably a pump is provided for pumping theexternal source of CO₂ prior to injection in the reservoir.

It will be appreciated that features described above in relation tocertain aspect(s) of the invention may be equally useful when applied toother aspect(s) of the invention, and vice versa.

Preferred embodiments of the present invention will now be described byway of example only and with reference to the accompanying drawings, inwhich:

FIGS. 1a and 1b are generalised diagrams each illustrating an EOR systemand method according to an embodiment of the invention wherein theentire process is carried out subsea;

FIGS. 2a and 2b are generalised diagrams each illustrating an EOR systemand method according to an embodiment of the invention wherein part ofthe process is carried out topside;

FIG. 3 is a process diagram illustrating an EOR system and methodaccording to an embodiment of the invention in which corrosion-resistantpiping is required;

FIG. 4 is a process diagram illustrating an EOR system and methodaccording to an embodiment of the invention in which a secondaryseparation process is carried out; and

FIG. 5 is a process diagram of an alternative embodiment of an EORsystem and method in which a secondary separation process is carriedout.

It will be noted that the described embodiments relate to offshore CO₂EOR processes, however the skilled person will appreciate that theembodiments may equally be employed in onshore fields.

FIG. 1a illustrates an EOR system 1 of an embodiment of the inventionwherein the entire process is carried out subsea. A well stream 4 isproduced from an oil reservoir 2 by the production tubing 3 and passedout via well head 5. At point 6 it is determined whether CO₂breakthrough has occurred yet. If it has not, then the well stream,numbered 4 a, is directed to an existing top-side oil processingfacility 7. Reference numeral 10 indicates sea level and numeral 22indicates the sea floor. In this case, since there is no back-producedCO₂, imported CO₂ 12 from an external source (preferably liquid CO₂)forms stream 13 which is injected into the reservoir 2 via injectionpiping 15, to provide EOR. This may be considered as a first phase ofoperation.

If CO₂ breakthrough has occurred, i.e. CO₂ gas is now beingback-produced, then the well stream, numbered 4 b, is directed to subseaprocess unit 8. This may be considered as a second phase of operation.Embodiments of this process unit will be described later with referenceto FIGS. 3 to 5. In this process unit 8 a gas phase 11 comprising CO₂,and hydrocarbon gas and small amounts of dissolved water is separatedfrom a liquid phase 9 comprising oil and water. The oil/water stream 9is provided to the oil processing facility 7. The gas phase 11 exits theprocess unit 8 and is mixed with imported CO₂ 12 (preferably liquid CO₂)from an external source, to form an injection stream 13. Further processsteps are carried out on this stream (not shown) and then it is providedvia injection well-head 14 to injection piping/injector 15, whichinjects the injection stream 13 into the reservoir 2. Whilst the mixingof the gas phase 11 with the imported CO₂ 12 into injection stream 13 isshown outside subsea process unit 8, this may in fact typically be partof subsea process unit 8. FIG. 1b illustrates the system of FIG. 1a ,but wherein these steps are incorporated into a complete subsea processunit 8′, incorporating also those processes of unit 8.

FIG. 2a illustrates an EOR system 20 of an embodiment in which part ofthe main process is carried out topside on a separate installation(platform or floater). Essentially, in this embodiment, the entiresubsea process unit 8 of FIG. 1 is instead located above sea level 10,i.e. topside, and forms topside process unit 19. The other parts andprocesses of the system 20 are the same as those of FIG. 1, and so willnot be described again here. As with FIG. 1a , whilst the mixing of thegas phase 11 with the imported CO₂ 12 into injection stream 13 is shownsubsea, outside topside process unit 19, it may in fact be part ofprocess unit 19. Thus, this part of the process may also be carried outtopside.

FIG. 2b is a modified version of the embodiment of FIG. 2a , whereinsome processing steps are carried out subsea, and some carried outtopside. As with FIGS. 1 and 2 a, in this EOR system 30, a well stream 4is produced from an oil reservoir 2 by the production piping 3 andpassed out via well head 5. At point 6 it is determined whether CO₂breakthrough has occurred yet. If it has not, then the well stream,numbered 4 a, is directed to a top-side oil processing facility. In thiscase, since there is no back-produced CO₂, imported CO₂ 12 only from anexternal source forms stream 13 which is injected into the reservoir 2via injection piping 15, to provide EOR.

If CO₂ breakthrough has occurred, i.e. CO₂ gas is now beingback-produced, then the well stream, numbered 4 b, is directed togas/liquid separator 16, which separates the well stream 4 b into aliquid phase 9 comprising oil and water and a gas phase 18 comprisingCO₂ and hydrocarbon gas and dissolved water.

The liquid phase 9 is directed to the oil processing facility 17. Thegas phase 18 is supplied to a topside process unit 19 above the surface,for example on a platform or a floater. This topside process unit 19carries out various further process steps, resulting in a gas phase 11comprising CO₂ and hydrocarbon gas which is mixed with imported CO₂ 12from an external source, to form injection stream 13. Further processsteps are carried out on this stream 13 (not shown) and it is thenprovided via injection well-head 14 to injection piping/injector 15,which injects the stream 13 into the reservoir 2.

As with FIG. 1a , whilst the mixing of the gas phase 11 with theimported CO₂ 12 into injection stream 13 is shown subsea, outsidetopside process unit 19, it may in fact be part of process unit 19.Thus, this part of the process may also be carried out topside.

Optionally, in the embodiment of FIG. 2b , the topside process unit 19may carry out a further gas/liquid separation step on the gas phase 18that it receives. In this case, the separated liquid phase 21 exits thetopside process unit 19, mixes with the liquid phase 9 from thegas/liquid separator 16, and is input to the oil processing facility 7.

FIG. 3 illustrates an EOR system 40 of an embodiment in whichcorrosion-resistant piping and equipment is required for the liquidphase downstream the separator 16. This embodiment is based on thegeneral system configuration of FIG. 1b , wherein the entire process iscarried out subsea. Parts common to both Figures are given the samereference numbers. The components within the dotted line box numbered 8′in FIG. 3 form the subsea process unit 8′ of FIG. 1b . The entire systemmay be known as an “EOR process facility”.

In the system of FIG. 3, a well stream 4 is produced from an oilreservoir 2 by production piping 3. It will be determined from ananalysis of the well stream 4 whether CO₂ breakthrough has occurred yet,as described in relation to FIG. 1, though this is not illustrated inFIG. 3 for simplicity. If it has not, then the well stream, is directedto a top-side oil processing facility (again, not shown in this Figure),which may be considered as a first phase of operation. In this case,since there is no back-produced CO₂, imported CO₂ 12 from an externalsource forms stream 13′ which is injected into the reservoir 2 viainjector 15, to provide EOR. This may be considered as a second phase ofoperation.

If, as is likely, the pressure of the external CO₂ source is notsufficient for direct injection into the reservoir, a booster pump 36 isprovided to increase the pressure prior to injection. The booster pump36 delivers sufficient pressure to inject the CO₂ into the reservoir.The pressure required will depend on the pressure in the reservoir atthe injection point, the necessary excess pressure to drive the CO₂ intothe reservoir, the static pressure increase from the injection templateto the injection point, and the frictional pressure drop in theinjection pipe.

FIG. 3 also illustrates a subsea cooler 34 through which the stream 13passes; however it is not necessary to cool the stream 13 if itcomprises only external CO₂ 12, so in this situation the cooler 34 willbe inactive. Since the cooler 34 is not required for external CO₂ 12only, in an alternative configuration the external CO₂ 12 could besupplied downstream the cooler 34.

Once CO₂ breakthrough has occurred, i.e. CO₂ gas is now beingback-produced, then the well stream 4 is directed to various processequipment which together form a “subsea process unit” 8. The point atwhich the well stream 4 should be directed to the subsea process unit 8may be determined based on the composition of the well stream. Forexample, a certain gas composition, particularly a certain CO₂/methaneratio may be expected once CO₂ breakthrough has occurred. In thisinitial phase after CO₂ breakthrough, the methane content in the gaswill be high and the CO₂ content low. Also, the total gas flow will below, compared with later life.

First, the well stream 4 is choked by choke 25 to a pre-definedpressure, and is then directed to gas/liquid separator 16. The selectionof the pressure level provided by the choke 25 will decide the partialpressure/content of CO₂ in the gas-phase and the CO₂ content in theliquid phase produced by the gas/liquid separator 16. A lower pressurewill reduce the CO₂ content in the liquid. The separation pressure willalso influence the compressor requirements (compressor 30, discussedlater) and the power required for the gas to be injected, and willdecide if the liquid phase 9 sent to the oil processing facility needsto be pressure boosted or not. If pressure boosting is required, a pumpwill be provided for liquid phase 9 (not shown in FIG. 3).

Moreover, the separation pressure will determine whether carbon steelcan be used in the piping downstream the separator 16 (i.e. the pipingconnecting with the oil processing facility) or whether corrosionresistant materials are required. The higher the pressure, the more CO₂there will be in the liquid phase 9. Due to the corrosive effect of CO₂,if the CO₂ in the liquid phase 9 is too high, some pipeline materialssuch as carbon steel will suffer from corrosion to an unacceptableextent. Thus, at higher pressures, the larger amounts of CO₂ in theliquid phase 9 requires the downstream piping to be manufactured fromcorrosion resistant material, such as stainless steel. In the embodimentof FIG. 3, the CO₂ content in the liquid phase 9 is high enough that thedownstream piping must be made of corrosion resistant materials. Whilstthis may be disadvantageous, the higher pressure means that noadditional pumping is required for the liquid phase 9 (though in otherembodiments a pressure boost may be required as discussed above).

However, in another embodiment, the separation pressure could be loweredto a level where corrosion resistant materials are not necessary, andthus the downstream piping could be made of carbon steel. A pump wouldthen be required to increase the pressure of the liquid phase 9 afterleaving the separator. Such embodiments are described later withreference to FIGS. 4 and 5.

Corrosion-resistant materials will always be required in the EOR processfacility (i.e. the whole system of FIGS. 3, 4 and 5 except for thepiping for liquid phase 9 in FIGS. 4 and 5) due to the separated gasphase comprising dissolved water, unless the gas phase is dehydrated.

Continuing the discussion of FIG. 3, the gas phase 26 separated by theseparator 16 comprises both CO₂ and hydrocarbon gas and dissolved water.This is, if necessary, cooled in a subsea cooler 27. Preferably, this isan active cooler, here shown with pump circulation by a sea-water pump18, so that the temperature can be adequately controlled to avoidhydrate formation and optimise the gas temperature prior to later mixingwith external CO₂. The cooled gas 29 is input to compressor 30 whichincreases the pressure thereof, forming cooled, compressed gas 11.Preferably, the compressor 30 is a liquid tolerant compressor sinceliquid may form after the cooler 27. If the compressor is not liquidtolerant, an additional gas/liquid separator may be required upstreamthe compressor to separate any liquid that has formed during cooling(not shown in the Figure). An additional liquid pump may also then beneeded to bring the liquid phase back to the main gas/liquid separator16 or directly to the liquid phase 9 being directed to the oilprocessing facility.

In FIG. 3, one-stage compression is shown utilising a single compressor30. However compression in more than one stage (i.e. by more than onecompressor in series) is also possible and may be used if the requiredpressure is higher than can be achieved by one compressor. However, forsimplicity, a design such as that illustrated requiring only onecompressor 30 is preferable (this is also less expensive).

The well stream gas flow rate after CO₂ breakthrough will be highlydynamic (mainly increasing) especially in the first period of operation,before a more stable situation is reached. To give an example, if theoperational time for the CO₂ EOR facility is 10 years after CO2breakthrough, the largest dynamics would happen in the first 1 to 2years. To handle this dynamic situation, a compressor recycle isprovided. As can be seen, a recycle flow 32 from downstream thecompressor 30 is directed into the well stream 4 upstream the gas liquidseparator 16. This provides more stable conditions for the separatoroperation, as it allows the separator to operate within narrower gas andliquid load ranges during the lifetime of the oil reservoir 2, whichsimplifies the operation and control of the separator. Alternatively,the compressor recycle flow 32 can be mixed into the gas 26 downstreamthe gas/liquid separator 16.

To protect the compressor against surge, an anti-surge line 31 is alsoprovided. Gas from downstream the compressor 30 is directed into theseparated gas 26 upstream from the cooler 27. Alternatively, gas fromdownstream the compressor 30 may be mixed with the well stream 4upstream the gas/liquid separator 16. It will be appreciated that in oneembodiment, a combined compressor recycle and anti-surge line may beprovided.

Downstream the compressor 30, the gas phase 11 is mixed at mixer 33 withCO₂ 12 from an external supply. The pressure of the external CO₂ and thecompressed gas phase 11 needs to be balanced. In a first phase after CO₂breakthrough, the gas flow 11 from the compressor will be low andcontain high concentrations of methane. This gas needs to be condensedprior to injection into the reservoir 2. However, a very high pressurefrom the compressor would be required for condensation by sea-wateralone, and there would be a high risk of hydrate formation. However, bymixing the gas 11 with the external CO₂ 12, the gas 11 willcondense/dissolve in the external CO₂ during the mixing process or insubsequent cooling by cooler 34. Thus, the compression requirement islower.

The process temperatures are controlled by both sea-water coolers 34, 27to avoid hydrate formation. It is desirable to reach a lower temperatureafter the mixing and cooling, to increase the density of the fluid,preferably liquid, leaving the cooler 34, but at the same time stayabove the hydrate formation temperature. Therefore, the cooler 34 ispreferably an active cooler, with sea water circulation by a sea waterpump 35. In an alternative embodiment, the gas 11 is cooled prior to(rather than after) being mixed with the external CO₂ 12.

The pressure of the fluid leaving the cooler 34 is increased by boosterpump 36, then the resulting fluid 13′ comprising a high proportion ofCO₂ is injected into the reservoir 2 via injection well head 14 andinjection piping 15, yielding enhanced oil recovery. Typically, theproportion of CO2 in the injection fluid 13′ will be between 85-95 mole% of the total fluid (though this will be case specific). The CO₂ isultimately back-produced via production tubing 3 and recycled throughthe process again.

After some time, the gas flow rate from the reservoir 2 will stabiliseand contain more and more CO₂, up to 80-90 mole % or more. When the gasflow rate increases, the required amount of external CO₂ 12 reduces.

Whilst in the embodiment of FIG. 3 the entire process is carried outsubsea (as in the general configuration of FIG. 1b ), the mixing ofexternal CO₂ and the processes downstream of this could be carried outsubsea whilst the remainder of the method is carried out topside on aplatform or floater, e.g. as in FIG. 2a . Or, the external CO₂ couldalso be taken topside for mixing, cooling and pumping. Or, thegas/liquid separation could be carried out subsea, the mixing withexternal CO₂ and the downstream processes carried out subsea, and theremainder of the method carried out topside (as in FIG. 2b ).

Example process data for an implementation of the embodiment of FIG. 3will now be given:

-   -   Temperature of well stream 4 prior to being choked: 90° C.    -   Pressure of well stream 4 prior to being choked: 60 bara (600        kPa)    -   Pressure of well stream after being choked: 30 bara (300 kPa)    -   Temperature of gas phase 29 exiting the first cooler 27: 20-40°        C.    -   Pressure of gas phase 11 exiting the compressor 30: 85 bara        (8500 kPa)    -   Temperature of external CO₂ 12: 9° C.    -   Pressure of external CO₂ 12: 85 bara (8500 kPa)    -   Temperature of injection stream 13′ exiting cooler 34: 15-30° C.    -   Temperature of injection stream 13′ entering injection piping        15: 15-35° C.    -   Pressure of injection stream 13′ entering injection piping 15:        120-160 bara (12000-16000 kPa)    -   Pressure in reservoir 2 at injection point: 320-360 bara        (32000-36000 kPa)    -   Depth of oil reservoir 2: 2600 m

It will be appreciated that these values are approximate, and are forone particular example only.

FIG. 4 illustrates an embodiment of an EOR system 50 in which asecondary separation process is carried out. Much of this system 50 isthe same as that of FIG. 3, and will not be described again here. Partscommon to both Figures are given the same reference numbers. Thedifference between the embodiments of FIGS. 3 and 4 is that in FIG. 4,there is a secondary gas/liquid separation process. In other words, thegas/liquid separation is carried out in multiple stages, in thisembodiment two stages, but in other embodiments the system may beextended to more than two stages.

Gas/liquid separator 16, as in FIG. 3, separates the well stream 4 intogas phase 26 comprising both CO₂ and hydrocarbon gas, and a liquidphase. However, the liquid phase is not then directed directly to an oilprocessing facility as stream 9. Instead, the liquid phase 41 from thegas/liquid separator 16 is choked down to a lower pressure by choke 42which results in the formation of more gas. The reduced pressuregas/liquid flow 43 is input to a further gas/liquid separator 44, whichseparates the gas phase 47. The partial pressure of CO₂ in the gas phaseresults in CO₂ content in the liquid phase 45 being low enough to allowfor a carbon steel pipeline to the oil processing facility and in theoil processing facility itself. In other words, since there is less CO₂in the liquid 45, the liquid is less corrosive, so corrosion-resistantpiping is not required and carbon steel can instead be used. Due to thereduced pressure of the liquid 45, an export pump 46 is provided to pumpthe liquid, as liquid 9, to the oil processing facility.

The liquid phase 45 will still be corrosive to some extent though, assome CO₂ will still be dissolved in it, so a corrosion control methodsuch as the injection of a film forming corrosion inhibitor may be usedto limit the corrosion rate of the pipeline and process equipment.

The gas stream 47 is, if required, cooled by cooler 48, here shown as anactive cooler with sea-water circulation by sea water pump 49. Howeverin other embodiments a passive cooler may be used. The pressure islikely to be low enough that hydrates are not an issue, so activecooling may be less essential.

The flow rate of the gas stream 47 from the gas/liquid separator 44 issubstantially lower than that of the gas stream 26 from the gas/liquidseparator 16. To bring the latter up to the same or similar flowrate/pressure as the former, more than one compressor is required if therequired pressure ratio for the compression is too high for onecompressor. Thus, the cooled gas stream 51 from the cooler 48 iscompressed by compressor 52 to form compressed stream 53, followed bycompressor 54 to form further compressed stream 55. If the totalpressure ratio is low enough, intermediate cooling between thecompressors is not needed, but may be required for higher pressureratios. The compressors are preferably both liquid tolerant compressors,or at least the compressor 52 should be a liquid tolerant compressor.Optionally, dry gas compressors may be used, and if so then upstreamseparators/scrubbers will be needed.

The compressors 52 and 53 are smaller than compressor 30, and the powerrequirement is typically less than 10% of that of the compressor 30. Theoperational conditions of compressors 52 and 53 will likely be constantenough to avoid the need for compressor recycle, but if not a compressorrecycle system similar to shown in FIG. 3 could be introduced

To protect the compressors 52 and 53 against surge, and anti-surge line56 is provided. Gas from downstream compressor 53 is directed into theseparated gas 47 upstream from the cooler 48. Alternatively, gas fromdownstream the compressor 53 may be mixed with the liquid phase 43upstream the gas/liquid separator 44.

In other embodiments, more than two compressors may be necessary.

The compressed gas 55 is mixed into separated gas stream 26, to formcombined gas stream 56. This is then processed in the same way as in gasstream 26 in FIG. 3, and ultimately injected into the reservoir 2.

FIG. 5 illustrates an alternative embodiment of an EOR system in which asecondary separating process is carried out. Much of this system is thesame as that of FIG. 4, and will not be described again here. Partscommon to both Figures are given the same reference numbers. Thedifference between the embodiments of FIGS. 4 and 5 is that in FIG. 5,the compressors 52 and 53 are replaced with an ejector 48.

In this embodiment, the gas stream 47 is directed to ejector 48. Ejector48 is powered by motive gas flow 49 from downstream the compressor 30.The ejector utilises this high pressure gas flow 49 to increase thepressure of stream 47. This significantly simplifies the system, and mayalso remove the need for any intermediate cooler. Since the ejectormotive gas flow 49 is taken from downstream the compressor 30, this willbe ultimately be recycled through the compressor 30, in addition to thecompressor recycle flow 32. Thus, more gas might be recycled through thecompressor 30 in the embodiment of FIG. 5 than in the embodiment of FIG.4. This could potentially increase the compressor power requirement.

In some embodiments, more than one ejector may be used.

Whilst in the embodiments of FIGS. 4 and 5 the entire process is carriedout subsea (as in the general configuration of FIG. 1), the subseaprocess unit 8 could instead be located topside on a platform or afloater (as in FIG. 2a ) or onshore, instead of subsea. Or, either orboth of the gas/liquid separations could be carried out subsea but theother process steps carried out topside (as in FIG. 2b ). Moreover,whilst in the embodiments shown the reservoir 2 is an offshorereservoir, the process is equally applicable to onshore reservoirs.

1. A method of Enhanced Oil Recovery (EOR) from an oil reservoir by CO₂flooding, comprising: producing a well stream from the reservoir;separating the well stream into a liquid phase and a gas phase with afirst gas/liquid separator, wherein the gas phase comprises both CO₂ gasand hydrocarbon gas; cooling the gas phase with a first cooler;compressing the gas phase using a first compressor into a compressedstream; mixing the compressed stream with an external source of CO₂ toform an injection stream; and injecting the injection stream into thereservoir.
 2. A method as claimed in claim 1, wherein the gas phase iscooled prior to compression.
 3. A method as claimed in claim 1 or 2,wherein the first cooler is an active cooler and/or wherein the firstcompressor is a liquid tolerant compressor.
 4. A method as claimed inany preceding claim, wherein the gas phase separated by the firstgas/liquid separator comprises water vapour in addition to CO₂ andhydrocarbon gas.
 5. A method as claimed in any preceding claim, whereinthe well stream is choked to a pre-defined pressure prior to separatingthe well stream into a liquid phase and a gas phase.
 6. A method asclaimed in any preceding claim, wherein prior to separating the wellstream into a liquid phase and a gas phase, the well stream is heated,preferably by a heat exchanger, more preferably by a heat exchangerutilising heat supplied by the first compressor.
 7. A method as claimedin any preceding claim, wherein the oil reservoir is an offshorereservoir.
 8. A method as claimed in claim 7, wherein the method iscarried out subsea; or wherein at least the steps of separating the wellstream, cooling the gas phase with the first cooler and compressing thegas phase are carried out above the sea, preferably on a platform orfloater; or wherein the step of separating the well stream is carriedout subsea, and the steps of cooling the gas phase with the first coolerand compressing the gas phase are carried out above the sea, preferablyon a platform or floater.
 9. A method as claimed in any preceding claim,wherein after compressing the gas phase, part of the compressed gasphase is recycled into the well stream upstream the gas/liquid separatoror into the gas phase downstream the gas/liquid separator.
 10. A methodas claimed in any preceding claim, wherein after compressing the gasphase, part of the compressed gas phase forms an anti-surge flow whichis directed into the gas phase downstream the gas/liquid separator andupstream the cooler.
 11. A method as claimed in any preceding claim,wherein the compressed stream is cooled by a second cooler prior tomixing with the external source of CO₂ or the injection stream is cooledafter mixing with the external source of CO₂; wherein preferably thecooled injection stream is pumped by a booster or injection pump.
 12. Amethod as claimed in any preceding claim, wherein the gas phase iscompressed in two stages using two compressors.
 13. A method as claimedin any preceding claim, wherein the injection stream comprises 85 to 95mole % CO₂.
 14. A method as claimed in any preceding claim, wherein theliquid phase is transported to an oil processing facility, preferablythrough corrosion-resistant piping.
 15. A method as claimed in anypreceding claim, wherein the liquid phase is choked to a lower pressuresuch that a second gas phase comprising CO₂ and hydrocarbon gas isreleased from the liquid phase, and wherein the second gas phase andliquid phase are separated in a second gas/liquid separator.
 16. Amethod as claimed in claim 15, wherein the second gas phase separated bythe second gas/liquid separator is combined with the gas phase separatedby the first gas/liquid separator.
 17. A method as claimed in claim 16,further comprising cooling the second gas phase with a third cooler andthen compressing the second gas phase prior to combining with the gasphase separated by the first gas/liquid separator.
 18. A method asclaimed in claim 17, wherein the second gas phase is compressed by onecompressor or two compressors arranged in series.
 19. A method asclaimed in claim 17 or 18, wherein after compressing the second gasphase, part of the second gas phase is recycled into the liquid phaseupstream the second gas/liquid separator or into the second gas phasedownstream the second gas/liquid separator.
 20. A method as claimed inany of claims 17 to 19, wherein after compressing the second gas phase,part of the second gas phase, forms an anti-surge flow which is directedinto the second gas phase downstream the second gas/liquid separator andupstream the third cooler.
 21. A method as claimed in claim 16, whereinthe pressure of the second gas phase is increased by an ejector prior tobeing combined with the gas phase separated by the first gas/liquidseparator; preferably wherein the ejector is powered by motive gas flowfrom downstream the first compressor.
 22. A method as claimed in any ofclaims 15 to 21, wherein after separating the second gas phase and theliquid phase, the liquid phase is pumped to an oil processing facility,preferably wherein a film forming corrosion inhibitor is injected intothe liquid phase.
 23. A method of Enhanced Oil Recovery (EOR) from anoil reservoir by CO₂ flooding, comprising: producing a well stream fromthe reservoir; separating the well stream into a liquid phase and afirst gas phase with a first gas/liquid separator; reducing the pressureof the liquid phase to release a second gas phase and separating thissecond gas phase from the liquid phase with a second gas/liquidseparator; combining the first and second gas phases into a combined gasphase; cooling the combined gas phase with a first cooler; compressingthe combined gas phase into an injection stream with a first compressor;and injecting the injection stream into the reservoir.
 24. A method asclaimed in claim 23, when the first gas phase and the second gas phaseeach comprise both CO₂ and hydrocarbon gas; the first gas phase andsecond gas phase further optionally comprising water vapour
 25. A methodas claimed in claim 23 or 24, where the first cooler is an activecooler; and/or wherein the first compressor is a liquid tolerantcompressor.
 26. A method as claimed in claim 24 or 25, furthercomprising mixing an external source of CO₂ into the injection streamprior to injecting the injection stream into the reservoir.
 27. A methodas claimed in claim 26, wherein the external source of CO₂ comprisesliquid CO₂.
 28. A method as claimed in claim 27, wherein the injectionstream into which the external source of CO₂ is mixed comprises a gasphase, and wherein the step of mixing the external source of CO₂ intothe injection stream causes the gas phase of the injection stream to atleast partially condense or dissolve in the external source of liquidCO₂.
 29. A method as claimed in claim 26, 27 or 28, wherein the methodfurther comprises cooling the injection stream with a second cooler,preferably by active cooling, either before or after the external sourceof CO₂ is mixed into the injection stream; wherein preferably thiscooling step condenses at least part of a gas phase in the injectionstream.
 30. A method as claimed in any of claims 23 to 29, where thewell stream is choked to a pre-defined pressure prior to separating thewell stream into a liquid phase and a first gas phase.
 31. A method asclaimed in any of claims 23 to 30, wherein prior to separating the wellstream into a liquid phase and a first gas phase, the well stream isheated, preferably via a heat exchanger.
 32. A method as claimed in anyof claims 23 to 31, wherein the oil reservoir is an offshore reservoir.33. A method as claimed in claim 32, wherein the method is carried outsubsea; or wherein the step of separating the well stream into a liquidphase and a first gas phase are carried out subsea, and subsequent stepsare carried out above the sea, preferably on a platform or floater; orwherein at least the following steps are carried out above the sea,preferably on a platform or floater; separating the well stream into aliquid phase and a first gas phase with a first gas/liquid separator;reducing the pressure of the liquid phase to release a second gas phaseand separating this second gas phase from the liquid phase with a secondgas/liquid separator; combining the first and second gas phases into acombined gas phase; cooling the combined gas phase with a first cooler;and compressing the combined gas phase into an injection stream with afirst compressor.
 34. A method as claimed in any of claims 23 to 33,wherein the liquid phase is transported to an oil processing facilitythrough carbon steel piping; preferably wherein a film forming corrosioninhibitor is injected into the liquid phase.
 35. A method as claimed inany of claims 23 to 34, wherein the second gas phase is cooled by athird cooler and then compressed prior to being combined with the firstgas phase; optionally wherein the second gas phase is compressed by onecompressor or two compressors arranged in series.
 36. A method asclaimed in claim 35, wherein after compressing the second gas phase,part of the compressed second gas phase forms an anti-surge flow whichis directed into the second gas phase downstream the second gas/liquidseparator and upstream the third cooler.
 37. A method as claimed in anyof claims 23 to 34, wherein the pressure of the second gas phase isincreased by an ejector prior to being combined with the first gas phaseseparated by the first gas/liquid separator; preferably wherein theejector is powered by motive gas flow from downstream the firstcompressor.
 38. A method used in Enhanced Oil Recovery (EOR) from an oilreservoir by CO₂ flooding, comprising: producing a well stream from thereservoir; separating the well stream into a liquid phase and a gasphase with a gas/liquid separator; compressing the gas phase using acompressor; and recycling part of the compressed gas phase into the wellstream upstream the gas/liquid separator or into the gas phasedownstream the gas/liquid separator.
 39. A method as claimed in claim38, further comprising injecting into the reservoir a part of thecompressed gas phase that is not recycled.
 40. A method as claimed inclaim 38 or 39, further comprising cooling the gas phase with a firstcooler, prior to compressing the gas phase.
 41. A method as claimed inclaim 40, wherein part of the compressed gas phase is recycled into thegas phase downstream the gas/liquid separator and upstream the firstcooler.
 42. A method as claimed in claim 40 or 41, wherein aftercomprising the gas phase, part of the compressed gas phase forms ananti-surge flow which is directed into the gas phase downstream thegas/liquid separator and upstream the first cooler.
 43. A method asclaimed in claim 42 when dependent on claim 41, wherein the a combinedrecycle and anti-surge line is provided to recycle the part of thecompressed gas phase and provide the anti-surge flow.
 44. A method asclaimed in any of claims 38 to 43, further comprising choking the wellstream with a choke to a pre-defined pressure prior to separating thewell stream into the liquid phase and the gas phase.
 45. A method asclaimed in claim 44, wherein part of the compressed gas phase isrecycled into the well stream upstream of the gas/liquid separator anddownstream the choke.
 46. A method as claimed in any of claims 38 to 45,wherein the gas phase comprises CO₂ and hydrocarbon gas; and optionallywater vapour.
 47. A method as claimed in any of claims 38 to 46, furthercomprising cooling the gas phase using a first cooler prior tocompressing the gas phase, wherein the first cooler is preferably anactive cooler.
 48. A method as claimed in any of claims 38 to 47,further comprising mixing an external source of CO₂ into the gas phaseto form an injection stream, wherein the injection stream is injectedinto the reservoir.
 49. A method as claimed in claim 48, furthercomprising cooling the injection stream with a second cooler andoptionally pumping the injection stream prior to injecting into thereservoir.
 50. A method of Enhanced Oil Recovery (EOR) from an oilreservoir by CO₂ flooding, comprising: a first phase comprisinginjecting CO₂ from a source external to the oil reservoir into thereservoir, and a second phase comprising the method as claimed in anypreceding claim.
 51. A method as claimed in claim 50, wherein prior tocommencement of the second phase, it is determined that theback-produced CO₂ in a well-stream produced from the reservoir exceeds athreshold value; or wherein it is determined that the CO₂/methane ratioin a well-stream produced from the reservoir exceeds a threshold value.52. An enhanced oil recovery system, comprising: a producer arranged toproduce a well stream from a reservoir; a first gas/liquid separatorarranged to separate the well stream into a liquid phase and a gas phasecomprising both CO₂ gas and hydrocarbon gas; a first cooler arranged tocool the gas phase; a first compressor arranged to compress the gasphase into a compressed stream; a mixer arranged to mix the compressedstream with an external source of CO₂ to form an injection stream; andinjection piping arranged to inject the injection stream into thereservoir.
 53. A system as claimed in claim 52, wherein the first cooleris arranged upstream of the first compressor to cool the gas phase priorto compression.
 54. A system as claimed in claim 52 or 53, wherein thefirst cooler is an active cooler and/or wherein the first compressor isa liquid tolerant compressor.
 55. A system as claimed in claim 52, 53 or54, further comprising a choke arranged upstream the first gas/liquidseparator to choke the well stream to a pre-defined pressure.
 56. Asystem as claimed in any of claims 52 to 55, further comprising a heatexchanger arranged upstream the first gas/liquid separator to heat thewell stream, preferably wherein the system further comprises a means toprovide heat from the first compressor to the heat exchanger.
 57. Asystem as claimed in any of claims 52 to 56, wherein the system islocated subsea; or wherein the first gas/liquid separator, first coolerand first compressor is located above the sea, preferably on a platformor a floater; or wherein the first gas/liquid separator is locatedsubsea whilst the first cooler and first compressor are located abovethe sea, preferably on a platform or floater.
 58. A system as claimed inany of claims 52 to 57, further comprising a recycle line connectingbetween downstream the first compressor and either upstream thegas/liquid separator or downstream the gas/liquid separator, the recycleline being arranged to recycle part of the compressed gas phase intoeither the well stream upstream the gas/liquid separator, or the gasphase downstream the gas/liquid separator.
 59. A system as claimed inany of claims 52 to 58, further comprising an anti-surge line connectingbetween downstream the first compressor and a point downstream thegas/liquid separator and upstream the first cooler, the anti-surge linebeing arranged to provide an anti-surge flow of compressed gas phaseinto the gas phase downstream the gas/liquid separator and upstream thefirst cooler.
 60. A system as claimed in any of claims 52 to 59, furthercomprising a second cooler downstream the first compressor or downstreamthe mixer to cool the injection stream; preferably further comprising abooster pump or injection pump arranged downstream the second cooler topump the injection stream.
 61. A system as claimed in any of claims 52to 60, further comprising corrosion-resistant piping arranged totransport the liquid phase to an oil processing facility.
 62. A systemas claimed in any of claims 52 to 61, further comprising: a second chokearranged to choke the liquid phase to a lower pressure so as to releasea second gas phase; and a second gas/liquid separator arranged toseparate the second gas phase from the liquid phase.
 63. A system asclaimed in claim 62, further comprising piping connecting the second gasphase with the first gas phase such that the gas phases mix together.64. A system as claimed in claim 62 or 63, further comprising a thirdcooler arranged downstream the second gas/liquid separator to cool thesecond gas phase, and a compressor arranged downstream the third coolerto compress the second gas phase.
 65. An enhanced oil recovery system,comprising: a producer arranged to produce a well stream from areservoir; a first gas/liquid separator arranged to separate the wellstream into a liquid phase and a gas phase; a choke arranged to reducethe pressure of the liquid phase so as to release a second gas phase; asecond gas/liquid separator arranged to separate the second gas phasefrom the liquid phase; piping or a mixer arranged to combine or mix thefirst and second gas phases into a combined gas phase; a first coolerarranged to cool the combined gas phase; a first compressor arranged tocompress the combined gas phase into an injection stream; and injectionpiping arranged to inject the injection stream into the reservoir.
 66. Asystem as claimed in claim 65, wherein the first cooler is an activecooler and/or wherein the first compressor is a liquid tolerantcompressor.
 67. A system as claimed in claim 65 or 66, furthercomprising an external source of CO₂, preferably liquid CO₂, and a mixerarranged to mix CO₂ from the external source of CO₂ with the injectionstream.
 68. A system as claimed in claim 67, further comprising a secondcooler arranged upstream the mixer to cool the injection stream prior tomixing with the CO₂, or downstream the mixer to cool the injectionstream after mixing with the CO₂; preferably wherein the second cooleris an active cooler.
 69. A system as claimed in any of claims 65 to 68,further comprising a second choke arranged to choke the well streamupstream the first gas/liquid separator.
 70. A system as claimed in anyof claims 65 to 69, further comprising carbon steel piping arranged totransport the liquid phase to an oil processing facility.
 71. A systemas claimed in any of claims 65 to 69, further comprising a third coolerarranged downstream the second gas/liquid separator to cool the secondgas phase, and a compressor arranged downstream the third cooler tocompress the second gas phase.
 72. A system as claimed in any of claims65 to 70, further comprising an ejector arranged to increase thepressure of the second gas phase, preferably wherein the ejector ispowered by motive gas flow from downstream the first compressor.
 73. Asystem for use in enhanced oil recovery, comprising: a producer arrangedto produce a well stream from a reservoir; a gas/liquid separatorarranged to separate the well stream into a liquid phase and a gasphase; a compressor arranged to compress the gas phase; a recycle linearranged to direct compressed gas from downstream the compressor toeither upstream the gas/liquid separator or downstream the gas/liquidseparator, such that the recycle line recycles part of the compressedgas phase into either the well stream upstream the gas/liquid separator,or the gas phase downstream the gas/liquid separator.
 74. A system asclaimed in claim 73, further comprising injection piping for injectinginto the reservoir a part of the compressed gas phase that is notrecycled.
 75. A system as claimed in claim 73 or 74, further comprisinga cooler arranged upstream the compressor to cool the gas phase.
 76. Asystem as claimed in claim 75, further comprising an anti-surge linearranged to direct compressed gas as an anti-surge flow from downstreamthe compressor to downstream the gas/liquid separator and upstream thecooler.
 77. A system as claimed in claim 75, wherein the anti-surge lineand recycle line are provided as a combined line.
 78. A system asclaimed in any of claims 73 to 77, further comprising a choke arrangeddownstream the gas/liquid separator to reduce the pressure of the wellstream.
 79. A system as claimed in claim 78, wherein the recycle line isarranged to direct compressed gas into the well stream upstream thegas/liquid separator and downstream the choke.
 80. A system as claimedin any of claim 73 or 79, further comprising an external source of CO₂,preferably liquid CO₂, and a mixer arranged to mix CO₂ from the externalsource of CO₂ to form an injection stream.
 81. A system as claimed inclaim 80, further comprising a second cooler arranged to cool theinjection stream; and optionally a pump arranged to pump the injectionstream prior; the system further comprising injection piping forinjecting the injection stream into the reservoir.
 82. An enhanced oilrecovery system, comprising: an external source of CO₂; injection pipingarranged to inject the external source of CO₂ into an oil reservoir; ameans for monitoring a CO₂ content or CO₂/methane ratio back-produced ina well stream from the oil reservoir; a determination means fordetermining when a CO₂ content or CO₂/methane content threshold isexceeded; and a system according to any of claims 52 to 81; wherein thesystem further comprises piping to bypass the elements of the system ofany of claims 52 to 81 downstream the producer and direct the wellstream to an oil processing facility, in the event that the threshold isnot met.
 83. A method or system substantially as hereinbefore describedwith reference to the accompanying drawings.